Page 1087 – RTO Insider

June 19, 2020

FERC Announces Tech Conferences on Carbon, OSW

FERC on Wednesday announced it will hold two technical conferences later this year: one to examine carbon pricing in the wholesale electricity markets and another to consider its transmission policies in relation to the growth of offshore wind.

The first conference, to be held Sept. 30 and led by the commissioners themselves, is in response to a petition and subsequent supportive comments earlier this year from a diverse array of stakeholders, including independent power producers, environmentalists and renewable energy trade associations. (See IPPs, Renewable Groups Seek F E RC Carbon Pricing Conference.)

“When such a broad group of voices asks the commission to convene an exchange of ideas, I think it is important that we do so,” Chairman Neil Chatterjee said during the commission’s monthly open meeting Thursday.

The main topic will be whether FERC even has the legal authority to regulate prices on carbon in regions with commission-jurisdictional markets, Chatterjee told reporters during a teleconference after the meeting. He noted that the petitioners merely asked FERC to “start the conversation” and not for the commission to create a specific rule. “I’m not going to prejudge where the conversation will lead , but I do think it’s significant we’re having this conversation,” he said.

The announcement was celebrated by the groups that submitted the original petition, including the Electric Power Supply Association, American Council on Renewable Energy and R Street Institute.

“Very happy to see this and appreciate FERC’s leadership in convening this conversation,” tw e eted Jeff Dennis, general counsel for Advanced Energy Economy and a former commission staffer. “I led the development of a few of these conferences in my time and recognize that they are not simple endeavors and require a great deal of staff and commissioner time.”

However, Justin Gundlach, a senior attorney for the New York University School of Law’s Institute for Policy Integrity, warned stakeholders not to “get too excited,” not i ng that the commission’s language in its announcement meant that the conference “is not going to be about RTOs or other federal entities adopting a carbon price.”

“The purpose of this conference is to discuss considerations related to state adoption of mechanisms to price carbon dioxide emissions, commonly referred to as ‘carbon pricing,’ in regions with commission-jurisdictional organized wholesale electricity markets,” FERC said (AD 2 0-14).

“I didn’t have a role in the drafting of the press release issued yesterday, but [Gundlach’s interpretation] wasn’t my understanding,” Commissioner Richard Glick told RTO Insider. A FERC spokesperson noted that the commission is still working on a detailed agenda for the conference.

The second conference announced Wednesday will be held Oct. 27 and will be led by staff. Participants will “discuss whether existing commission transmission, interconnection and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open-access transmission principles” and “consider possible changes or improvements to the current framework should they be needed to accommodate such growth” (AD20-1 8).

Asked by reporters what prompted this conference, Chatterjee said that “the time is ripe to start a dialogue” given the expected growth of offshore wind resources. There are about 26 GW worth of projects going through the federal permitting process, and states have collectively established procurement targets of more than 28 GW, acc o rding to the American Wind Energy Association.

Chatterjee was also asked whether the conference will address concerns that offshore wind will be priced out of PJM’s capacity market because of the commission’s expansion of the RTO’s minimum offer price rule. He did not directly answer the question, noting that the commission was still working on an agenda but stressed, as he has “time and time again,” that the commission’s “efforts to protect markets are fuel-neutral.”

June 17, 2020

PG&E Pleads Guilty to 84 Homicides and Arson

Pacific Gas and Electric Corp. CEO Bill Johnson stood before a judge in Chico, Calif., Tuesday and replied “guilty, your honor,” 84 times to charges of involuntary manslaughter as he watched photographs of those who died in the 2018 Camp Fire display on a courtroom screen.

One of largest corporate homicide cases in U.S. history is scheduled to conclude Friday, when Butte County Superior Court Judge Michael Deems sentences PG&E on the manslaughter charges and one count of starting an illegal fire. The November 2018 Camp Fire was the deadliest and most destructive wildfire in state history.

A plea deal calls for PG&E to pay the maximum fine of nearly $4 million. It is already on probation for six felony counts stemming from the San Bruno gas pipeline explosion in September 2010.

The company also plans to pay $13.5 billion to victims of the Camp Fire and a series of Northern California fires in October 2017 when it exits bankruptcy, probably within the next two weeks. (See Lawyers Close PG&E Bankruptcy Case.)

PG&E guilty — PG&E CEO Bill Johnson, standing, pleads guilty to 85 felonies in Butte County Superior Court on Tuesday, with the courtoom closed to most because of COVID-19. | *Butte County Superior Court*

Those who lost family members and homes in the fire will have Wednesday, Thursday and part of Friday to address the court prior to sentencing.

Johnson expressed remorse on behalf of PG&E Tuesday and vowed the company would change.

“Our equipment started the fire that destroyed the towns of Paradise and Concow and severely burned Magalia and other parts of Butte County,” Johnson told the judge. “That fire took the lives of 85 people. Thousands lost their homes and businesses, and many others were forced to evacuate under horrific circumstances. I wish there were some way to take back what happened or take away the pain of those who’ve suffered. But I know there’s not.”

Prosecutors said one of the 85 who died committed suicide as flames approached, but they lacked evidence to prove he killed himself to avoid being killed by the fire.

Butte County District Attorney Michael Ramsey released a re p ort Tuesday listing the names and ages of the dead. They included 99-year-old Rose Farrell, who was found on her front porch in Paradise near her empty wheelchair. Five others who died were women in their 90s; a dozen other victims were in their 80s.

Matilde Heffern, 68, her daughter Christina Heffern, 40, and granddaughter, Ishka Heffern, 20, died together in their home as it burned.

“Their remains were located commingled in the bathtub of their residence,” the prosecutor’s report said. “The Hefferns placed a 911 call as the fire approached their home. Somehow the phone line remained open as the house, and the three women, burned as helpless [emergency] dispatchers listened to their screams.”

Others perished in their vehicles, overcome by smoke and flames, as they tried to flee. A firefighter was “horribly burned” helping his fellow firefighters escape to safety, the district attorney said.

Ramsey said the cause of so much suffering and death was a 100-year-old broken C hook on a PG&E transmission line. The part cost less than a dollar when it was manufactured in 1919 and sells for about $13 today, he said.

“That is what killed 84 Butte County citizens,” Ramsey said, holding up the broken hook at a press conference following the arraignment.

‘Negligent and Reckless’

The report by Ramsey’s office examined in detail the decades of inspection and maintenance failures by PG&E that led to the C hook breaking. The report relied on investigations by the California Department of Forestry and Fire Protection (Cal Fire), the FBI and PG&E testimony before a grand jury.

The company skimped on inspections and upgrades for years to cut costs and boost profits, the report said. In 2013 it formed a committee to “explore opportunities to reduce costs by reducing the frequency of inspections and patrols” and gave bonuses to transmission line superintendents and supervisors based partly on staying under budgets, it said.

“As expected, the result of these reductions was less thorough and less complete inspections and patrols,” the report said.

The lax inspections and poor maintenance compounded problems on PG&E’s aging infrastructure, including the century-old Caribou-Palermo line, where the Camp Fire started.

“The fact that PG&E relied on a … 100-year-old C hook it knew nothing about to hold an energized 115-kV conductor is, by itself, negligent and reckless,” the report said.

PG&E likely knew the hardware was aging because sometime in the past its crews had replaced worn hanger plates on the line’s transmission towers, and a 1986 inspection of a similarly aged PG&E line had found worn C hooks, it said.

The Caribou-Palermo line was built between 1919 and 1921 by the Great Western Power Co., which PG&E bought in 1930. The line, now shut down, connected hydroelectric stations in the steep Feather River Canyon to population centers in the San Francisco Bay area. It crossed rugged foothills where winds gusted to more than 50 mph.

“Despite the fact that PG&E has owned … the Caribou-Palermo line since 1930, the evidence established PG&E did not catalogue or replace the original conductors, insulators or attachment hardware on many of the towers,” the report said.

In December 2012, five towers on the line collapsed, and a sixth was badly damaged in a domino effect that likely started when one tower’s “stub angles,” which connected the tower to its base, broke due to high winds and wet, icy ground, a PG&E engineer concluded. The engineer recommended inspections on other towers, but PG&E didn’t follow through, the report said.

“Again, this is consistent with PG&E’s practice of not following up on clearly established potential safety and/or maintenance issues,” it said.

The conductor on the Caribou-Palermo line was aluminum reinforced with a steel core, which has a lifespan of 36 years and carries a high risk of failure, according to a report by Quanta Technologies, a consultant PG&E hired in 2009 to assess its transmission system.

“What it says is that PG&E fully intended to run that conductor to failure,” the prosecutors’ report concluded. “A reasonable person doesn’t need an electrical engineer or Quanta Technologies to tell him that failure of an energized 115-kV [line] is extremely dangerous. PG&E’s decision to leave the 97-year-old aluminum, steel-reinforced conductor in service was extraordinarily reckless.”

“In essence, in 1930, PG&E blindly bought a used car. PG&E drove that car until it fell apart,” starting the Camp Fire, the report said.

June 17, 2020

FERC OKs Revised Forecast for PJM Incremental Auction

FERC granted PJM permission to use a lower peak load forecast for its second Incremental Auction scheduled for July, reflecting the impact of the COVID-19 pandemic (ER20 –1870).

On May 20, PJM reque s ted a one-time Tariff waiver to replace the summer peak load forecast it had filed earlier this year before states started issuing stay-at-home orders.

PJM stated that because it has already held the Base Residual Auction (BRA) and first Incremental Auction for the 2021/22 delivery year, capacity commitment levels, clearing prices and zonal capacity prices were already largely set for the year. PJM said the waiver would primarily affect parties newly releasing or taking on capacity commitments in the second Incremental Auction and was necessary because of “the impact of the unforeseeable economic consequences of the COVID-19 pandemic.”

PJM Incremental Auction — Estimated impact of COVID-19 on daily peak and energy | *PJM*

Without a change, its summer 2021 load forecast would be “significantly overstated,” PJM said.

“While the lack of record evidence is not dispositive, under the circumstances presented here, we find that any potential harm to prices in the second Incremental Auction for the 2021/22 delivery year is outweighed by using auction parameters that reflect the significant economic forecast change and associated decrease in the forecast summer peak resulting from the economic consequences of the COVID-19 pandemic,” FERC said in its June 15 order approving the waiver.

PJM forecasters have up d ated stakeholders on COVID-19 impacts for several months, saying weekday load peaks have come in 10.4% less, or around 9,300 MW, than what would be anticipated without COVID-19. At the May 12 Planning Committee meeting, PJM told members new parameters were being used for the forecast. (See “Load Forecast Update,” PJM PC/TE A C Briefs: May 12, 2020.)

The new parameters incorporate an updated economic forecast PJM received from Moody’s Analytics in April.

PJM said the April report’s forecast for third-quarter 2021 real gross domestic product is 7.1% lower than that assumed in Moody’s September 2019 forecast and that the drop, along with the “associated significant” decrease in forecast peak load, was “too large to ignore.” It said the waiver would “align the auction parameters with currently expected conditions.”

June 17, 2020January 29, 2024

UPDATED: FERC Sets Tri-State’s Exit-fee Rules for Hearing

[Editor’s Note: This article has been updated to clarify state-federal jurisdictional issues raised in this docket.]

In the face of opposition from Colorado officials and others, FERC last week set hearing and settlement judge procedures on Tri-State Generation & Transmission’s proposal for computing member exit fees (ER20-1559).

FERC accepted the contract termination payment (CTP) methodology for filing with a refund effective date of June 13, saying it raises issues of material fact that cannot be resolved based on the existing record and has not been shown to be just and reasonable.

In doing so, FERC’s June 12 order rejected a request by 14 Colorado legislators to decline jurisdiction, saying the commission’s consideration of Tri-State’s proposed exit-fee methodology “is consistent with our past practice.”

The Colorado legislators asked FERC to decline jurisdiction “to allow” the Colorado Public Utilities Commission to continue its consideration of complaints by United Power and LaPlata Electric Association asking the PUC to set a just and reasonable fee for their exit from Tri-State.

The PUC held a hearing on the complaints in May, and an administrative law judge’s decision is expected by next week. Before the hearing, the ALJ granted the complainants motion to reject Tri-State’s defense that the PUC lacked jurisdiction (19F-0620E, 19F-0621E).

‘All Requirements’ Contracts

The commission in March accepted Tri-State’s request that it be recognized as jurisdictional to the commission (EL20-16). (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.) Tri-State’s 43 utility members in Colorado, Nebraska, New Mexico and Wyoming signed all-requirements wholesale service contracts obligating them to purchase at least 95% of their requirements at cost-based rates through 2050.

Tri-State’s proposed CTP methodology is designed to calculate the payment an electric distribution cooperative or public power district must make to terminate its contract. The cooperative said its determination of exit fees on a case-by-case basis has led to disputes “with and among” members and that the proposed methodology was overwhelmingly approved by its members in April.

The CTP methodology uses a mark-to-market analysis incorporating demand and energy charges to ensure remaining members are financially unaffected by withdrawals and Tri-State can continue to fund its operations and debt service.

The Colorado PUC protested CTP, saying a similar methodology resulted in an initial exit charge for members Kit Carson Electric Cooperative and Delta-Montrose Electric Association that was 70% higher than the amount on which Tri-State settled. On June 9, the commission approved Delta-Montrose’s withdrawal, allowing the cooperative to exit Tri-State as planned on June 30 (EC20-51). (See Tri-State G&T, Delta-Montrose Reach Withdrawal Deal.)

Northwest Rural Public Power District argued that the methodology was improperly based on projected revenues and calculates payment over an excessively long time period, benefiting non-withdrawing members.

Wheat Belt Public Power District contended the methodology violates the cost-causation principle by socializing among all utility members some costs to provide wholesale electric service to members in Colorado and New Mexico.

Tri-State CEO Duane Highley called the commission’s acceptance of the filing “a decidedly positive outcome” and an “important step forward” for its members.

“Each [member] now has a voice and will be treated equally on wholesale contract and rate matters,” Highley said. “We believe this issue is now properly before the appropriate regulatory commission.”

‘Civil Conspiracy’

United in May also filed a lawsuit against Tri-State and the three non-utility members in a Colorado county district court, claiming a “civil conspiracy” to deprive state regulators of jurisdiction over Tri-State’s exit fees. United said it plans to seek punitive damages after suffering “hundreds of millions of dollars in damages.”

Tri-State responded with a lengthy statement, saying United’s complaint “smacks of desperation and is completely without merit.”

“Tri-State will vigorously defend its members and its board of directors’ lawful, appropriate and open decisions and actions to seek federal regulation. Further, United Power’s complaint insults our other cooperative members, who clearly understood the direction of the association,” Tri-State said.

Tri-State and the other three entities have until Friday to file a response, in what could be another protracted legal proceeding.

June 17, 2020

GreenHat Maneuvers to Remove FERC from Shell Case

GreenHat Energy has filed a motion to bar FERC’s Office of Enforcement from working on a breach-of-contract case involving Shell Energy North America, alleging commission officials conspired with an independent consultant hired by the PJM Board of Managers to change the report on GreenHat’s 2018 default.

In its June 4 filing, GreenHat alleges that in March 2019, it learned that one or more members of Enforcement’s investigative team had met with Robert Anderson, an independent third-party expert retained by PJM’s board to prepare the Report of the Independent Consultants on the GreenHat Default. The filing further alleges that FERC officials had a draft copy of the report and asked Anderson to “alter or remove language in the draft favorable to GreenHat.”

The company said that in early July 2019, it received an anonymous whistleblower letter alleging that a representative of Enforcement asked the team conducting the default review to “avoid including any information that could be exculpatory to GreenHat.”

“Enforcement’s unsavory conduct over a year ago may be out of the commission’s hands at this point. But walling off Enforcement and others who worked on the investigation is not,” GreenHat wrote in its filing.

FERC and Anderson declined to comment on the GreenHat filing. Officials from PJM said the filing was still being reviewed by the RTO.

The motion comes after a May 29 petition by Shell asking FERC to intercede in a Texas state court case in which GreenHat filed a breach-of-contract claim against the energy company regarding bilateral contracts to transfer financial transmission rights. Shell is asking the commission to interpret PJM’s Tariff provisions regarding bilateral transfers of FTRs (EL20-49).

GreenHat Energy — GreenHat’s significant growth in exposure and MTA loss | *PJM*

Shell said in its petition that GreenHat does not allege the FTR agreements were breached but instead “makes the extraordinary claim that entering data into PJM’s platform for reporting FTR transfers created additional separate, binding contracts, which Shell Energy allegedly breached.”

Shell entered into three agreements with GreenHat between August 2016 and February 2017 in which it agreed to what it called a “consignment” arrangement in which GreenHat would transfer FTRs to Shell, which would attempt to sell them in the next PJM long-term FTR auction.

GreenHat transferred the FTRs to Shell and reported the transfer in PJM’s FTR center without any compensation.

Shell agreed to pay GreenHat 73% of the revenues it generated from FTRs that sold in the auction. Shell agreed to return to GreenHat any FTRs that failed to clear or to purchase them at “an agreed-upon price, also based on auction clearing prices.”

Shell said it fulfilled its obligations under the first two bilateral agreements on Oct. 18, 2016, and Feb. 10, 2017, by making one-time lump-sum payments to GreenHat of the final purchase price for cleared FTRs and those uncleared FTRs that it did not return to GreenHat.

The company executed the third agreement on Feb. 27, 2017. In the meantime, FTR trader DC Energy told PJM in February 2017 that it believed “GreenHat’s portfolio would lose between $35 [million] and $40 million by the time the positions settled in two to three years.” (See Shell Demands Seat at GreenHat Settlement Table.)

In a June 1 notice, FERC set a June 29 deadline for comments in the proceeding. The deadline for comments was later changed to July 14 after FERC granted GreenHat’s motion for extension on June 11.

June 17, 2020

NYISO Stakeholders OK Peak Forecast Tweak

NYISO’s Management Committee voted Tuesday to revis e the ISO’s Tariff to address a concern regarding the peak load forecast and minimum unforced capacity requirements for load-serving entities.

The forecast is determined using the New York Control Area’s (NYCA) highest actual hourly load in the prior calendar year adjusted to “design conditions,” which are expected to occur on a non-holiday weekday in July or August.

NYISO Associate Planning Analyst Ying Guo said the ISO was concerned about situations in which the highest hourly actual load occurs outside the “design conditions” as in 2019, when the highest actual load occurred on a Saturday in July.

The minimum capacity requirement is allocated among individual LSEs, determined by their consumption during the highest hourly actual load in the NYCA, regardless of whether that is consistent with consumption at design conditions.

The Tariff revision would require the use of the highest NYCA load hour occurring on a non-holiday weekday during July or August when calculating the NYCA peak load forecast. About 80% of the highest coincident NYCA peak load hours have occurred in July and August.

The change will ensure that each LSE’s share of the minimum capacity requirement is consistent with the design conditions used to calculate the minimum capacity requirement.

If the highest load hour occurs on a weekend or holiday, it would be adjusted to account for expected additional load that would have occurred if the highest load hour had been a non-holiday weekday. Similarly, load also would be adjusted when the highest load hour occurs outside July and August.

If the temperature is higher than the design temperature, load will be removed to reflect the expected lower load that would have occurred if the highest load hour had taken place at the “design” temperature. The ISO said the change should ensure that the incentive to reduce peak demand aligns with when the peak demand is expected to occur.

Following board approval, the changes are expected to be filed with FERC in July, with the ISO seeking an effective date in time for the 2021/22 capability year.

Dave Clarke of the Long Island Power Authority said the change “makes some sense in the short run” but asked whether the rules would need to change again if increasing solar generation transitioned the ISO into a winter-peaking region.

“If we shift to a … winter-peaking system, this wouldn’t be appropriate,” agreed Nate Gilbraith, NYISO resource adequacy and ICAP specialist. “In 10 years or so, if we need to make this change again, we will and that will be made with a whole suite of things we’d need to accommodate a winter-peaking system.”

Gilbraith said the change approved by stakeholders Tuesday “doesn’t have any administrative or coordination challenges.” But he said a project considering moving from a one-hour peak calculation to one involving five or 10 peak hours would be more complicated. “That’s why that’s a project — bigger scope,” he said.

June 17, 2020

Xcel Energy Completes $400M Tx Project

Xcel Energy subsidiary Southwestern Public Service has completed a major transmission project in Texas and New Mexico, part of a multibillion effort to expand and modernize the region’s grid.

The $400 million, three-year project came in 9% under budget and involved the construction of 240 miles of 345-kV transmission lines from SPS’ TUCO substation north of Abernathy, Texas, to the China Draw substation southeast of Carlsbad, N.M.

Xcel Energy transmission — Crews erect an H-frame structure as part of work on the TUCO-China Draw transmission line. | *Xcel Energy*

The TUCO-China Draw project is part of Xcel’s Power for the Plains initiative, designed to update the region’s grid to improve reliability, meet demand and provide new renewable energy outlets. SPS’ network comprises more than 7,000 miles of high-voltage lines that cover the Panhandle and South Plains regions in Texas, portions of eastern and southeastern New Mexico, and also reach into the Oklahoma Panhandle and southwestern Kansas.

Xcel said much of the initiative’s work has focused on strengthening its connections with SPP, enabling it to tap abundant and economical sources of electricity that have lowered purchased power costs by as much as $60 million annually. The investments have quadrupled Xcel’s import capabilities and boosted the region’s power supply during peak demand months, the company said.

“Xcel Energy is committing a large amount of capital as a sign of our faith in the economies of eastern New Mexico and West Texas,” said David Hudson, president of Xcel’s New Mexico and Texas operations. “We are focusing resources on projects that will not only provide our communities the safe, clean, abundant and affordable power they require for development but also keep the cost of electricity at or below the rate of inflation. The Power for the Plains transmission enhancement program is a foundational aspect of that strategy.”

The region’s energy and agriculture economies are expected to expand in the coming years, though the crash in oil prices has dampened some of those projections.

Xcel said it has invested more than $3 billion in grid and power generating improvements in Texas and New Mexico since 2011. That includes an expansion of wind resources that puts the company on track for an 80% reduction in carbon emissions by 2030.

June 17, 2020

`Macro Grid’ Seeks to Connect Grid’s Regions

Two environmental advocacy coalitions are combining forces on an initiative to build support for expanding, upgrading and stitching together the nation’s transmission grid to bring renewable energy to high-demand urban centers.

The American Council on Renewable Energy (ACORE) and Americans for a Clean Energy Grid (ACEG) on Tuesday said their Macro Grid Initiative would push for transmission allowing the U.S. to “harness its abundant renewable resources and balance electric demand across the country.”

The Macro Grid Initiative will undertake “wide-ranging” educational efforts supporting transmission expansion and recognizing the “substantial” benefits of new regional and interregional transmission. ACORE and ACEG said this can be accomplished by connecting grid regions like MISO, PJM and SPP.

The 15 states between the Rocky Mountains and Mississippi account for 88% of the nation’s wind technical potential and 56% of solar technical potential, the organizations said. However, the region is home to only about 30% of the expected electricity demand in 2050.

ACORE CEO Gregory Wetstone called for improving the nation’s “outdated and balkanized electricity transmission system” to compete in the 21st century economy and “properly tackle” the climate crisis.

“A Macro Grid will allow for better integration of low-cost renewable energy, resulting in a more resilient, efficient grid and a dramatic reduction in carbon emission,” he said.

“We believe every supporter of clean energy should be a supporter of a stronger backbone transmission grid,” said Rob Gramlich, ACEG’s executive director. “Americans for a Clean Energy Grid looks forward to working with ACORE to explain to the public and policymakers why that is the case and to build support for its development.”

The initiative’s priorities include an expanded national and Eastern grid with a focus on the MISO, PJM and SPP regions.

The effort was endorsed by officials of the American Wind Energy Association, Solar Energy Industries Association, Advanced Power Alliance, WIRES, R Street Institute, Union of Concerned Scientists, Natural Resources Defense Council, ITC Holdings Corp. and the Clean Grid Alliance.

ACEG and ACORE say upgrading America’s transmission system is a cost-effective way to alleviate transmission congestion and integrate new generation. They cited several recent studies to support their case:

A ScottMadden study for WIRES that said expanding and upgrading interregional transmission lines would help utilities, corporate and institutional buyers and other consumers meet carbon and clean-energy goals by affordably and reliably integrating low-cost renewable resources.
The National Renewable Energy Laboratory’s analysis of interconnection seams that found increased transmission development could save consumers more than $47 billion and return $2.50 for every dollar invested.
A paper in the journal Nature Climate Change on carbon dioxide emissions that said a nationwide HVDC network optimized for the nation’s best wind and solar resources could reduce CO₂ emissions by 80% without increasing electric bills.

Former FERC Chair Pat Wood said in a statement that the 2000-2001 California/Western power collapse and the 2003 North American power blackout revealed that power markets require a robust infrastructure.

“Today, that means strong electrical ties between and across all the power regions,” said Wood, now CEO of Hunt Energy Network. “I welcome the refreshed focus on this issue: without a strong national power grid, we won’t come anywhere close to the low-cost, low-carbon grid customers demand — and deserve.”

June 16, 2020

NEPOOL Markets Committee Briefs: June 10, 2020

New England’s total wholesale costs of electricity last year fell 19% to $9.8 billion, driven mostly by lower energy costs, according to the ISO-NE Internal Market Monitor’s 2019 Annual Markets Report.

Energy and capacity costs collectively composed about 93% of the overall decrease, as shown by highlights from the report presented by IMM Director Jeffrey McDonald to the New England Power Pool Markets Committee last week.

Energy costs fell primarily on lower natural gas prices and lower loads, totaling about $4.1 billion and down about 33% from 2018.

Chart discussed at NEPOOL Markets Committee — The 2019 energy market cost decrease in New England was driven by lower energy prices resulting from lower natural gas prices. | *ISO-NE*

Last year contrasted with a 2018 that saw both an extended winter cold snap and a hot and humid summer, which elevated natural gas prices in winter and boosted electricity prices in both seasons. Natural gas prices declined 34% last year to an average of $3.26/MMBtu.

Electricity demand in the third quarter of the year decreased by 6%, or by 1,011 MW per hour, on average, and drove a 4% decrease in annual demand. On a weather-normalized basis, demand was down slightly, continuing a longer-term downward trend because of the increase in utility-backed energy efficiency programs and behind-the-meter photovoltaic generation, McDonald said.

Ancillary service costs in New England were 25% lower in 2019 from the previous year. | *ISO-NE*

ISO-NE also reported that the Forward Capacity Auction procured surplus capacity for the sixth consecutive year as clearing prices continued a downward trend. FCA 14 in February cleared at an all-time low price of $2/kW-month. (See ISO-NE Capacity Prices Hit Record Low.)

FCA 14’s surplus was almost 1,500 MW, or 5%, above the installed capacity requirement, despite a significant amount of capacity (more than 2,500 MW) exiting the capacity market, mostly for a one-year period, in response to low prices, according to the report.

Exempting EE from Pay-for-Performance

Mark Spencer of LS Power led discussion of a Jericho Power proposal to exempt EE resources from Pay-for-Performance (PfP) in order to eliminate up to $19 million in credit support costs for all capacity resources.

ISO-NE rolled out PfP in June 2018 to ensure fuel security under severe winter conditions. Under the program, all resources with capacity supply obligations (CSOs) are assessed a charge — based on their gross FCA payments — when a “measurable” real-time operating reserve (RTOR) deficiency triggers a capacity scarcity condition (CSC). The RTO then redistributes the money collected from that charge as payments to CSO resources based on their performance during the RTOR event.

Critics contend that the current PfP arrangement has the potential to overcompensate the performance of EE resources during CSC events, which could be remedied by altogether removing those resources from PfP because their RTOR deficiencies are not technically measurable.

A Sept. 3, 2018, CSC event used as an example showed that “EE received a charge of $551,000” while “non-EE capacity supply obligation holders shared in the pool charge to the tune of $7.3 million,” Spencer said.

Spencer posed a hypothetical circumstance of when EE can be overcompensated: “We’re now on the cusp, with FCA 15, of moving from the $2,000 [CSC charge] rate that was in effect during the September 2018 event, to … $5,455/MWh; EE’s charge would have been $1.5 million, [and] non‐EE CSO holders would have been charged $20 million” if the new rate was applied to the 2018 event, Spencer said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

“If applying on-peak rules to that hypothetical case, then EE’s net payment would have been $10.3 million, so just toggling the same event between off-peak and on-peak, it goes from $1.5 million to a net payment of $10.3 million,” he said.

This increase in net payments to EE as system load decreases is in “direct contradiction to the evidentiary record” of EE performance, LS Power contended. Under the proposal, net charges or net payments to EE in any hour of any CSC would be zero.

ISO-NE has estimated that for the 2019/20 capacity commitment period, the face value of credit support required because of EE’s participation in PfP was $11 million to $19 million, and the cost of providing this support is higher for smaller, nonpublic companies that may have lower credit ratings.

“If EE did not participate in PfP, this requirement, and its associated cost, would be eliminated,” Spencer said.

The proposal would retain EE’s base capacity payments, remove EE from the PfP settlement including the “insurance pool” and eliminate EE’s requirement to provide credit support for the FCM Delivery Financial Assurance.

Backers of the proposal will continue to develop it before the MC this summer before seeking a vote on the Market Rule 1 and Financial Assurance Policy changes at the September PC meeting.

FRM Sunset by 2025

ISO-NE Market Development Analyst Jonathan Lowell led discussion of the RTO’s proposal to sunset the Forward Reserve Market on June 1, 2025.

The FRM awards obligations to deliver 10-minute non-spinning reserves and 30-minute operating reserves in real time.

The FRM sunset proposal is not linked to FERC approval of the RTO’s Energy Security Improvements filing or to development of seasonal forward market for ESI energy options, according to meeting materials.

However, the RTO is following the suggestion of the External Market Monitor, which in its annual report published June 3 reiterated what it has been recommending since 2014. The EMM said that the FRM is no longer necessary, and that the settlement rules by themselves don’t create incentives for resources to be available in real time, forcing reliance on administrative penalty provisions.

Markets have evolved in other ways to reward resource flexibility and better performance, and transmission investment has addressed many locational constraints, the Monitor showed.

“The weaknesses are manifest, and FRM weaknesses outweigh any negligible remaining benefits,” the RTO’s materials said.

The RTO wants to establish a sunset date of June 1, 2025; otherwise, the assumptions used in FCA 16 for cost of new entry (CONE) and other parameters would not properly reflect expected ancillary service market revenues, according to the proposal.

The updated FRM sunset stakeholder schedule now anticipates an MC vote in October and a Participants Committee vote in November.

Rethinking Net CONE for FCA 16

In a matter related to the FRM sunset proposal, ISO-NE is proposing to update the CONE and net CONE calculations, and to recalculate existing — and establish new — offer review trigger prices (ORTPs) using updated data for FCA 16, to be held in 2022 to cover the 2025/26 capacity commitment period.

CONE estimates the cost to build a new resource in New England, while net CONE indicates the net revenue needed by the resource to be economically viable. ORTPs are low-end estimates of net CONE for specific — and less common — technologies.

Engaged by the RTO to support the updates, Concentric Energy Advisors’ Danielle Powers and her colleagues presented analysis with preliminary technology costs for the calculations, determination of ORTP technologies and indicative FRM revenue-offset component values.

ISO-NE aims to make its estimates consistent with FERC’s 2017 order directing that net CONE should be high enough to attract new entry, but not so high as to introduce unnecessary costs (ER17-795). The RTO proposes to file any calculation changes with FERC by Dec. 1.

CEA will continue its evaluation and analysis of technologies for CONE and ORTP calculations and provide initial assumptions for the financial model.

At the July MC meeting, the consultants will provide energy and ancillary services offsets, including a detailed approach, inputs, dispatch models and preliminary results for CONE and ORTP.

June 16, 2020

Maine Presents Microcosm of Massive Climate Challenge

A webinar last week to discuss strategies for meeting Maine’s renewable portfolio standards and emission-reduction targets presented a stark reminder of just how challenging decarbonizing the entire power sector and curtailing global climate change will be.

The Environmental & Energy Technology Council of Maine (E2Tech) on Wednesday invited four panelists to present their own strategy for meeting Maine’s ambitious goals: a 45% greenhouse gas emissions reduction below 1990 levels by 2030, and at least 80% by 2050; and 80% renewable energy by 2030 and 100% by 2050.

Though each speaker emphasized different methods, all would involve an unprecedented buildout in solar and wind energy and a paradigm shift in how electricity is valued on the wholesale and retail markets. It would also involve massive electrification of all sectors of the state’s economy.

“One of the things that became clear as we prepared [for the webinar] is that we are overlapping quite a bit in our findings,” said Jürgen Weiss, a principal with The Brattle Group. “I think that by itself is an interesting observation. We’ll quibble about the last 5% or maybe the last 10% in the details here and there, but the overall conclusions that we come to are strikingly similar actually.”

Richard Silkman, CEO of advising firm Competitive Energy Services, said that converting all end uses of energy to electricity in the state would more than triple the 12 TWh used annually to about 40 TWh, while peak demand would go from about 2 GW to about 10 GW.

Weiss used a previous Brattle study that analyzed New England’s trajectory to obtaining 80% renewables by 2050 to present a comparison to Silkman’s projections. The study showed that the region would need about 200 GW of total capacity, over six times more than it has currently.

“The current pace of adding wind, solar, etc. falls far short of what is needed to build the needed renewable portfolio of 200 GW by 2050, but a steady growth rate of 10% or less per year would do it!” according to Brattle’s Jürgen Weiss. | *The Brattle Group*

“So if I want to scare anybody about how hard it will be to do it, I’ll frame it this way: We took 100 years to build the current electric system of something like 30 GW. Now we have 30 years to build an entirely new system of 200 GW,” Weiss said. “So that’s pretty scary.”

One of the biggest challenges for Maine and the rest of New England is that solar does not have as large a capacity factor as it does in other, sunnier parts of the U.S. New England’s demand also peaks in winter, when sunlight is less productive. That means the state will have to build an extraordinary amount of solar facilities to replace the large, retiring fossil fuel plants in the region, panelists said.

That presents its own challenges, said Richard Perez, senior research associate at the University of Albany’s Atmospheric Sciences Research Center. He focused his presentation on “ultra-high penetration PV,” as he said solar has the highest potential to meet global demand. “When we think of a ‘mix’ of solutions, for me the mix is solar,” he said. “Most of the other energy sources are byproducts of solar.”

Solar has the highest potential capacity of all generating resources, the University of Albany’s Richard Perez said. | *E2Tech*

The main challenge is converting solar from being a seasonal, intermittent resource to a firm, dispatchable one: “something that’s available 24/7/365, without downtime,” Perez said. A massive buildout of storage is one solution, he said, but “extremely expensive … even assuming very low future costs for storage.” Perez’s idea is to build more solar than is actually needed and purposefully curtail it, a model he calls “implicit storage.”

The problem is “nobody pays you to curtail,” making his solution “not dependent on technology; it’s more dependent on the policy and the rules of remuneration.”

The state will also have to evolve from its customer-driven model of renewable procurement. Perez related his own experience with making his New York home a net zero energy consumer: rooftop solar panels, an in-home battery and an electric vehicle. “None of those millions of customers [in his home city of Albany] could do what I did; they don’t have the space or maybe the financial position to do it. And the big industrial customers can not do that either.

“So if I [can] solve my problem and be proud about it, it’s far from solving what we need to do for [the] climate,” he said.

Another challenge is that Maine residents are also very protective of their state’s heavily forested land and scenic mountain views. Under Silkman’s analysis, onshore wind would also have to significantly increase, though not as much as solar, from 1 GW currently to 2.5 GW. That’s “problematic in Maine, I understand, given people’s love for mountaintops,” he said.

Perez noted grassroots, environmental opposition to PV development on the grounds of protecting land and trees. He said it would take 8,500 square miles to power the U.S. with 55% solar under his model of overbuilding. “So, it looks gigantic … until you put it in perspective and look at the ground distribution in the U.S.” That 8,500 square miles represents about 1% of farmland in the contiguous U.S., he said.

The yellow dot in the southwestern corner of the map represents the space necessary to generate 55% of Maine’s electricity with solar power. | *E2Tech*

In Maine, assuming the same proportion of solar in the generation mix, facilities would only take up 37 square km — compared to the state’s nearly 56,000 square km of forest. “There’s so much space, in fact, you could even foresee doing away with wind” and using 100% solar, he said.

‘Fall Far Short’

The panelists’ projections and strategies made it clear that Maine and New England are behind on achieving their goals.

“At the current rates of deployment of renewables that are now on the horizon for the next decade, we’re going to fall far short of building these large capacities of renewable resources by 2050,” Weiss said. “We have to roughly increase the annual average deployment rate [by] four to eight times … about [3,000] to 6,000 MW per year” between now and 2050. “So that’s scary.”

Regarding emissions reductions, Silkman said that the state’s 2050 goal is still possible if it significantly ramps up its electrification and renewable buildout. “But it’s not going to happen in the 2020s, no matter what we do,” he said. “This decade’s gone. But we can start to see some serious reductions in the 2030s and 2040s.”

Kurt Adams, CEO of Summit Utilities, concluded his remarks by encouraging attendees. “Stay humble and work hard,” he said. “We’re changing the status quo. It’s very, very difficult. And it’s very difficult for a lot of reasons. So it just takes a lot of work and a lot of checking yourself and thinking about how you’re moving things forward, rejecting your ideas if they’re not being successful and picking the next one up and driving forward.”